1. Field of the Invention
Embodiments of the present invention generally relate to a torque sub for use with a top drive.
2. Description of the Related Art
In wellbore construction and completion operations, a wellbore is initially formed to access hydrocarbon-bearing formations (i.e., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill support member, commonly known as a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annular area is thus formed between the string of casing and the formation. The casing string is temporarily hung from the surface of the well. A cementing operation is then conducted in order to fill the annular area with cement. Using apparatus known in the art, the casing string is cemented into the wellbore by circulating cement into the annular area defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
A drilling rig is constructed on the earth's surface to facilitate the insertion and removal of tubular strings (i.e., drill strings or casing strings) into a wellbore. The drilling rig includes a platform and power tools such as an elevator and a spider to engage, assemble, and lower the tubulars into the wellbore. The elevator is suspended above the platform by a draw works that can raise or lower the elevator in relation to the floor of the rig. The spider is mounted in the platform floor. The elevator and spider both have slips that are capable of engaging and releasing a tubular, and are designed to work in tandem. Generally, the spider holds a tubular or tubular string that extends into the wellbore from the platform. The elevator engages a new tubular and aligns it over the tubular being held by the spider. One or more power drives, i.e. a power tong and a spinner, are then used to thread the upper and lower tubulars together. Once the tubulars are joined, the spider disengages the tubular string and the elevator lowers the tubular string through the spider until the elevator and spider are at a predetermined distance from each other. The spider then re-engages the tubular string and the elevator disengages the string and repeats the process. This sequence applies to assembling tubulars for the purpose of drilling, running casing or running wellbore components into the well. The sequence can be reversed to disassemble the tubular string.
Historically, a drilling platform includes a rotary table and a gear to turn the table. In operation, the drill string is lowered by an elevator into the rotary table and held in place by a spider. A Kelly is then threaded to the string and the rotary table is rotated, causing the Kelly and the drill string to rotate. After thirty feet or so of drilling, the Kelly and a section of the string are lifted out of the wellbore and additional drill string is added.
The process of drilling with a Kelly is time-consuming due to the amount of time required to remove the Kelly, add drill string, reengage the Kelly, and rotate the drill string. Because operating time for a rig is very expensive, as much as $500,000 per day, the time spent drilling with a Kelly quickly equates to substantial cost. In order to address these problems, top drives were developed. Top drive systems are equipped with a motor to provide torque for rotating the drilling string. The quill of the top drive is connected (typically by a threaded connection) to an upper end of the drill pipe in order to transmit torque to the drill pipe.
Another method of performing well construction and completion operations involves drilling with casing, as opposed to the first method of drilling and then setting the casing. In this method, the casing string is run into the wellbore along with a drill bit. The drill bit is operated by rotation of the casing string from the surface of the wellbore. Once the borehole is formed, the attached casing string may be cemented in the borehole. This method is advantageous in that the wellbore is drilled and lined in the same trip.
FIG. 1A is a side view of an upper portion of a drilling rig 10 having a top drive 100 and an elevator 35. An upper end of a stack of tubulars 70 is shown on the rig 10. The FIG. shows the elevator 35 engaged with one of the tubulars 70. The tubular 70 is placed in position below the top drive 100 by the elevator 35 in order for the top drive having a gripping device (i.e., spear 200 or torque head 300) to engage the tubular.
FIG. 1B is a side view of a drilling rig 10 having a top drive 100, an elevator 35, and a spider 60. The rig 10 is built at the surface 45 of the wellbore 50. The rig 10 includes a traveling block 20 that is suspended by wires 25 from draw works 15 and holds the top drive 100. The top drive 100 has the spear 200 (alternatively, a torque head 300) for engaging the inner wall (outer wall for torque head 400) of tubular 70 and a motor 140 to rotate the tubular 70. The motor 140 may be either electrically or hydraulically driven. The motor 140 rotates and threads the tubular 70 into the tubular string 80 extending into the wellbore 50. The motor 140 can also rotate a drill string having a drill bit at an end, or for any other purposes requiring rotational movement of a tubular or a tubular string. Additionally, the top drive 100 is shown having a railing system 30 coupled thereto. The railing system 30 prevents the top drive 100 from rotational movement during rotation of the tubular 70, but allows for vertical movement of the top drive under the traveling block 110.
In FIG. 1B, the top drive 100 is shown engaged to tubular 70. The tubular 70 is positioned above the tubular string 80 located therebelow. With the tubular 70 positioned over the tubular string 80, the top drive 100 can lower and thread the tubular into the tubular string. Additionally, the spider 60, disposed in a platform 40 of the drilling rig 100, is shown engaged around the tubular string 80 that extends into wellbore 50.
FIG. 1C illustrates a side view of the top drive 100 engaged to the tubular 70, which has been connected to the tubular string 80 and lowered through the spider 60. As depicted in the FIG., the elevator 35 and the top drive 100 are connected to the traveling block 20 via a compensator 170. The compensator 170 functions similar to a spring to compensate for vertical movement of the top drive 100 during threading of the tubular 70 to the tubular string 80. In addition to its motor 140, the top drive includes a counter 150 to measure rotation of the tubular 70 as it is being threaded to tubular string 80. The top drive 100 also includes a torque sub 160 to measure the amount of torque placed on the threaded connection between the tubular 70 and the tubular string 80. The counter 150 and the torque sub 160 transmit data about the threaded joint to a controller via data lines (not shown). The controller is preprogrammed with acceptable values for rotation and torque for a particular joint. The controller compares the rotation and the torque data to the stored acceptable values.
FIG. 1C also illustrates the spider 60 disposed in the platform 40. The spider 60 comprises a slip assembly 66, including a set of slips 62, and piston 64. The slips 62 are wedge-shaped and are constructed and arranged to slide along a sloped inner wall of the slip assembly 66. The slips 62 are raised or lowered by piston 64. When the slips 62 are in the lowered position, they close around the outer surface of the tubular string 80. The weight of the tubular string 80 and the resulting friction between the tubular string 80 and the slips 62, force the slips downward and inward, thereby tightening the grip on the tubular string. When the slips 62 are in the raised position as shown, the slips are opened and the tubular string 80 is free to move longitudinally in relation to the slips.
FIG. 2A is a cross-sectional view of the spear 200, for coupling the top drive 100 and the tubular 70, in disengaged and engaged positions, respectively. The spear 200 includes a cylindrical body 205, a wedge lock assembly 250, and slips 240 with teeth (not shown). The wedge lock assembly 250 and the slips 240 are disposed around the outer surface of the cylindrical body 200. The slips 240 are constructed and arranged to mechanically grip the inside of the tubular 70. The slips 240 are threaded to piston 270 located in a hydraulic cylinder 210. The piston 270 is actuated by pressurized hydraulic fluid injected through fluid ports 220, 230. Additionally, springs 260 are located in the hydraulic cylinder 210 and are shown in a compressed state. When the piston 270 is actuated, the springs decompress and assist the piston in moving the slips 240. The wedge lock assembly 250 is constructed and arranged to force the slips 240 against the inner wall of the tubular 70 and moves with the cylindrical body 205.
In operation, the slips 240, and the wedge lock assembly 250 of top drive 100 are lowered inside tubular 70. Once the slips 240 are in the desired position within the tubular 70, pressurized fluid is injected into the piston 270 through fluid port 220. The fluid actuates the piston 270, which forces the slips 240 towards the wedge lock assembly 250. The wedge lock assembly 250 functions to bias the slips 240 outwardly as the slips are slid along the outer surface of the assembly, thereby forcing the slips to engage the inner wall of the tubular 70.
FIG. 2B is a cross-sectional view of the spear 200, in the engaged position. The FIG. shows slips 240 engaged with the inner wall of the tubular 70 and a spring 260 in the decompressed state. In the event of a hydraulic fluid failure, the spring 260 can bias the piston 270 to keep the slips 240 in the engaged position, thereby providing an additional safety feature to prevent inadvertent release of the tubular string 80. Once the slips 240 are engaged with the tubular 70, the top drive 100 can be raised along with the cylindrical body 205. By raising the body 205, the wedge lock assembly 250 will further bias the slips 240. With the tubular 70 engaged by the top drive 100, the top drive can be relocated to align and thread the tubular with tubular string 80.
Alternatively, the top drive 100 may be equipped with the torque head 300 instead of the spear 200. The spear 200 may be simply unscrewed from the quill (tip of top drive 100 shown in FIGS. 2A and 2B) and the torque head 300 is screwed on the quill in its place. The torque head 300 grips the tubular 70 on the outer surface instead of the inner surface. FIG. 3 is a cross-sectional view of a prior art torque head 300. The torque head 300 is shown engaged with the tubular 70. The torque head 300 includes a housing 305 having a central axis. A top drive connector 310 is disposed at an upper portion of the housing 305 for connection with the top drive 100. Preferably, the top drive connector 310 defines a bore therethrough for fluid communication. The housing 305 may include one or more windows 306 for accessing the housing's interior.
The torque head 300 may optionally employ a circulating tool 320 to supply fluid to fill up the tubular 70 and circulate the fluid. The circulating tool 320 may be connected to a lower portion of the top drive connector 310 and disposed in the housing 305. The circulating tool 320 includes a mandrel 322 having a first end and a second end. The first end is coupled to the top drive connector 310 and fluidly communicates with the top drive 100 through the top drive connector 310. The second end is inserted into the tubular 70. A cup seal 325 and a centralizer 327 are disposed on the second end interior to the tubular 70. The cup seal 325 sealingly engages the inner surface of the tubular 70 during operation. Particularly, fluid in the tubular 70 expands the cup seal 325 into contact with the tubular 70. The centralizer 327 co-axially maintains the tubular 70 with the central axis of the housing 205. The circulating tool 320 may also include a nozzle 328 to inject fluid into the tubular 70. The nozzle 328 may also act as a mud saver adapter 328 for connecting a mud saver valve (not shown) to the circulating tool 320.
Optionally, a tubular stop member 330 may be disposed on the mandrel 322 below the top drive connector 310. The stop member 330 prevents the tubular 70 from contacting the top drive connector 310, thereby protecting the tubular 70 from damage. To this end, the stop member 330 may be made of an elastomeric material to substantially absorb the impact from the tubular 70.
One or more retaining members 340 are employed to engage the tubular 70. As shown, the torque head 300 includes three retaining members 340 mounted in spaced apart relation about the housing 305. Each retaining member 340 includes a jaw 345 disposed in a jaw carrier 342. The jaw 345 is adapted and designed to move radially relative to the jaw carrier 342. Particularly, a back portion of the jaw 345 is supported by the jaw carrier 342 as it moves radially in and out of the jaw carrier 342. In this respect, a longitudinal load acting on the jaw 345 may be transferred to the housing 305 via the jaw carrier 342. Preferably, the contact portion of the jaw 345 defines an arcuate portion sharing a central axis with the tubular 70. The jaw carrier 342 may be formed as part of the housing 305 or attached to the housing 305 as part of the gripping member assembly.
Movement of the jaw 345 is accomplished by a piston 351 and cylinder 350 assembly. In one embodiment, the cylinder 350 is attached to the jaw carrier 342, and the piston 351 is movably attached to the jaw 345. Pressure supplied to the backside of the piston 351 causes the piston 351 to move the jaw 345 radially toward the central axis to engage the tubular 70. Conversely, fluid supplied to the front side of the piston 351 moves the jaw 345 away from the central axis. When the appropriate pressure is applied, the jaws 345 engage the tubular 70, thereby allowing the top drive 100 to move the tubular 70 longitudinally or rotationally.
The piston 351 may be pivotably connected to the jaw 345. As shown, a pin connection 355 is used to connect the piston 351 to the jaw 345. A pivotable connection limits the transfer of a longitudinal load on the jaw 345 to the piston 351. Instead, the longitudinal load is mostly transmitted to the jaw carrier 342 or the housing 305. In this respect, the pivotable connection reduces the likelihood that the piston 351 may be bent or damaged by the longitudinal load.
The jaws 345 may include one or more inserts 360 movably disposed thereon for engaging the tubular 70. The inserts 360, or dies, include teeth formed on its surface to grippingly engage the tubular 70 and transmit torque thereto. The inserts 360 may be disposed in a recess 365 as shown in FIG. 3A. One or more biasing members 370 may be disposed below the inserts 360. The biasing members 370 allow some relative movement between the tubular 70 and the jaw 345. When the tubular 70 is released, the biasing member 370 moves the inserts 360 back to the original position. Optionally, the inserts 360 and the jaw recess 365 are correspondingly tapered (not shown).
The outer perimeter of the jaw 345 around the jaw recess 365 may aide the jaws 345 in supporting the load of the tubular 70 and/or tubular string 80. In this respect, the upper portion of the perimeter provides a shoulder 380 for engagement with the coupling 72 on the tubular 70 as illustrated FIGS. 3 and 3A. The longitudinal load, which may come from the tubular 70 string 70,80, acting on the shoulder 380 may be transmitted from the jaw 345 to the housing 305.
A base plate 385 may be attached to a lower portion of the torque head 300. A guide plate 390 may be selectively attached to the base plate 385 using a removable pin connection. The guide plate 390 has an inclined edge 393 adapted and designed to guide the tubular 70 into the housing 305. The guide plate 390 may be quickly adjusted to accommodate tubulars of various sizes. One or more pin holes 392 may be formed on the guide plate 390, with each pin hole 392 representing a certain tubular size. To adjust the guide plate 390, the pin 391 is removed and inserted into the designated pin hole 392. In this manner, the guide plate 390 may be quickly adapted for use with different tubulars.
A typical operation of a string or casing assembly using a top drive and a spider is as follows. A tubular string 80 is retained in a closed spider 60 and is thereby prevented from moving in a downward direction. The top drive 100 is then moved to engage the tubular 70 from a stack with the aid of an elevator 35. The tubular 70 may be a single tubular or could typically be made up of three tubulars threaded together to form a joint. Engagement of the tubular 70 by the top drive 100 includes grasping the tubular and engaging the inner (or outer) surface thereof. The top drive 100 then moves the tubular 70 into position above the tubular string 80. The top drive 100 then threads the tubular 70 to tubular string 80.
The spider 60 is then opened and disengages the tubular string 80. The top drive 100 then lowers the tubular string 80, including tubular 70, through the opened spider 60. The spider 60 is then closed around the tubular string 80. The top drive 100 then disengages the tubular string 80 and can proceed to add another tubular 70 to the tubular string 80. The above-described acts may be utilized in running drill string in a drilling operation, in running casing to reinforce the wellbore, or for assembling strings to place wellbore components in the wellbore. The steps may also be reversed in order to disassemble the tubular string.
When joining lengths of tubulars (i.e., production tubing, casing, drill pipe, any oil country tubular good, etc.; collectively referred to herein as tubulars) for oil wells, the nature of the connection between the lengths of tubing is critical. It is conventional to form such lengths of tubing to standards prescribed by the American Petroleum Institute (API). Each length of tubing has an internal threading at one end and an external threading at another end. The externally-threaded end of one length of tubing is adapted to engage in the internally-threaded end of another length of tubing. API type connections between lengths of such tubing rely on thread interference and the interposition of a thread compound to provide a seal.
For some oil well tubing, such API type connections are not sufficiently secure or leakproof. In particular, as the petroleum industry has drilled deeper into the earth during exploration and production, increasing pressures have been encountered. In such environments, where API type connections are not suitable, it is conventional to utilize so-called “premium grade” tubing which is manufactured to at least API standards but in which a metal-to-metal sealing area is provided between the lengths. In this case, the lengths of tubing each have tapered surfaces which engage one another to form the metal-to-metal sealing area. Engagement of the tapered surfaces is referred to as the “shoulder” position/condition.
Whether the threaded tubulars are of the API type or are premium grade connections, methods are needed to ensure a good connection. One method involves the connection of two co-operating threaded pipe sections, rotating a first pipe section relative to a second pipe section by a power tongs, measuring the torque applied to rotate the first section relative to the second section, and the number of rotations or turns which the first section makes relative to the second section. Signals indicative of the torque and turns are fed to a controller which ascertains whether the measured torque and turns fall within a predetermined range of torque and turns which are known to produce a good connection. Upon reaching a torque-turn value within a prescribed minimum and maximum (referred to as a dump value), the torque applied by the power tongs is terminated. An output signal, e.g. an audible signal, is then operated to indicate whether the connection is a good or a bad connection.
FIG. 4A illustrates one form of a premium grade tubing connection. In particular, FIG. 4A shows a tapered premium grade tubing assembly 400 having a first tubular 402 joined to a second tubular 404 through a tubing coupling or box 406. The end of each tubular 402,404 has a tapered externally-threaded surface 408 which co-operates with a correspondingly tapered internally-threaded surface 410 on the coupling 406. Each tubular 402,404 is provided with a tapered torque shoulder 412 which co-operates with a correspondingly tapered torque shoulder 414 on the coupling 406. At a terminal end of each tubular 402,404, there is defined an annular sealing area 416 which is engageable with a co-operating annular sealing area 418 defined between the tapered portions 410,414 of the coupling 406.
During make-up, the tubulars 402, 404 (also known as pins), are engaged with the box 406 and then threaded into the box by relative rotation therewith. During continued rotation, the annular sealing areas 416, 418 contact one another, as shown in FIG. 4B. This initial contact is referred to as the “seal condition”. As the tubing lengths 402,404 are further rotated, the co-operating tapered torque shoulders 412,414 contact and bear against one another at a machine detectable stage referred to as a “shoulder condition” or “shoulder torque”, as shown in FIG. 4C. The increasing pressure interface between the tapered torque shoulders 412,414 cause the seals 416,418 to be forced into a tighter metal-to-metal sealing engagement with each other causing deformation of the seals 416 and eventually forming a fluid-tight seal.
During make-up of the tubulars 402,404, torque may be plotted with respect to turns. FIG. 5A shows a typical x-y plot (curve 500) illustrating the acceptable behavior of premium grade tubulars, such as the tapered premium grade tubing assembly 400 shown in FIGS. 4A-C. FIG. 5B shows a corresponding chart plotting the rate of change in torque (y-axis) with respect to turns (x-axis). Shortly after the tubing lengths engage one another and torque is applied (corresponding to FIG. 4A), the measured torque increases substantially linearly as illustrated by curve portion 502. As a result, corresponding curve portion 502a of the differential curve 500a of FIG. 5B is flat at some positive value.
During continued rotation, the annular sealing areas 416,418 contact one another causing a slight change (specifically, an increase) in the torque rate, as illustrated by point 504. Thus, point 504 corresponds to the seal condition shown in FIG. 4B and is plotted as the first step 504a of the differential curve 500a. The torque rate then again stabilizes resulting in the linear curve portion 506 and the plateau 506a. In practice, the seal condition (point 504) may be too slight to be detectable. However, in a properly behaved make-up, a discernable/detectable change in the torque rate occurs when the shoulder condition is achieved (corresponding to FIG. 4C), as represented by point 508 and step 508a. 
The following formula is used to calculate the rate of change in torque with respect to turns:
Rate of Change (ROC) Calculation
                Let T1, T2, T3, . . . Tx represent an incoming stream of torque values.        Let C1, C2, C3, . . . CX represent an incoming stream of turns values that are paired with the Torque values.        Let y represent the turns increment number>1.        The Torque Rate of Change to Turns estimate (ROC) is defined by:        ROC:=(Ty−Ty-1)/(Cy−Cy-1) in Torque units per Turns units.        
Once the shoulder condition is detected, some predetermined torque value may be added to achieve the terminal connection position (i.e., the final state of a tubular assembly after make-up rotation is terminated). The predetermined torque value is added to the measured torque at the time the shoulder condition is detected.
As indicated above, for premium grade tubulars, a leakproof metal-to-metal seal is to be achieved, and in order for the seal to be effective, the amount of torque applied to affect the shoulder condition and the metal-to-metal seal is critical. In the case of premium grade connections, the manufacturers of the premium grade tubing publish torque values required for correct makeup utilizing a particular tubing. Such published values may be based on minimum, optimum and maximum torque values, minimum and maximum torque values, or an optimum torque value only. Current practice is to makeup the connection to within a predetermined torque range while plotting the applied torque vs. rotation or time, and then make a visual inspection and determination of the quality of the makeup.
It would be advantageous to employ top drives in the make-up of premium tubulars. However, available torque subs (i.e., torque sub 160) for top drives do not possess the required accuracy for the intricate process of making up premium tubulars. Current top drive torque subs operate by measuring the voltage and current of the electricity supplied to an electric motor or the pressure and flow rate of fluid supplied to a hydraulic motor. Torque is then calculated from these measurements. This principle of operation neglects friction inside a transmission gear of the top drive and inertia of the top drive, which are substantial. Therefore, there exists a need in the art for a more accurate top drive torque sub.